Legal claims defining the scope of protection. Each claim is shown in both the original legal language and a plain English translation.
1. A method of exploitation of fluid in a subterranean formation crossed by a network of fractures in which, based on measurements of properties relating to the formation, a meshed representation of the formation is constructed and statistical parameters are determined relating the network of fractures, for at least one mesh of the meshed representation of the formation comprising: A. constructing a double medium meshed representation by breaking down each mesh into a set of identical matrix blocks with each matrix block being parallelpiped in shape, representing a non-fractured portion of the formation and being delimited by an orthogonal system of uniform fractures; B. determining an equivalent permeability tensor of the network of fractures in the mesh; C. determining principal orthogonal directions of flow and eigenvalues of the equivalent permeability tensor in the determined principal orthogonal directions of flow; and D. determining a characteristic dimension of the matrix blocks of the mesh according to a relationship which is a function of at least the eigenvalues of the equivalent permeability tensor; determining an optimum exploitation scheme of the fluid in the formation based on at least the double medium mesh representation, the characteristic dimension of the matrix blocks of the mesh and a flow simulation of the formation; and exploiting the fluid in the formation in accordance with the optimum exploitation scheme; and wherein the characteristic dimension of the matrix blocks of each mesh is determined by a relationship as follows: t i = ( 2 k f e f ∑ j = 1 3 ( - 1 ) δ ij K j ) , where Kj is the eigenvalue of the equivalent permeability tensor of the principal orthogonal direction j of flow, with j varying from 1 to 3, k f and of are respectively determined values of permeability of the formation and thickness representative of all fractures, and ti is the characteristic dimension of a matrix block in a principal direction of flow i with i varying from 1 to 3.
The method involves optimizing fluid exploitation in a subterranean formation intersected by a fracture network. The formation's properties are measured to construct a meshed representation, and statistical parameters of the fracture network are determined. For each mesh, a double medium meshed representation is created by dividing the mesh into identical parallelepiped-shaped matrix blocks, each representing a non-fractured portion of the formation and bounded by uniform orthogonal fractures. The equivalent permeability tensor of the fracture network within the mesh is calculated, followed by the determination of principal orthogonal flow directions and eigenvalues of the permeability tensor in these directions. The characteristic dimension of the matrix blocks is then derived using a relationship dependent on the eigenvalues of the permeability tensor. An optimal fluid exploitation scheme is determined based on the double medium mesh representation, the characteristic dimension of the matrix blocks, and a flow simulation of the formation. The characteristic dimension of the matrix blocks in each principal flow direction is calculated using the formula: t_i = (2 * k_f * e_f / Σ_{j=1 to 3} (-1)^δ_ij * K_j), where K_j is the eigenvalue of the permeability tensor in the principal flow direction j, k_f is the formation permeability, e_f is the fracture thickness, and t_i is the characteristic dimension in the principal flow direction i. The fluid is then exploited according to the optimized scheme.
2. The method as claimed in claim 1 , wherein the statistical parameters are chosen from fracture density, fracture length, fracture orientation in space, fracture openness and distribution of fractures in the formation.
This invention relates to subsurface geological analysis, specifically methods for characterizing fracture networks in rock formations. The technology addresses the challenge of accurately assessing fracture properties in subsurface formations, which is critical for applications such as oil and gas extraction, geothermal energy, and groundwater management. Fractures in rock formations significantly influence fluid flow and reservoir behavior, but traditional methods often lack precision in quantifying key fracture characteristics. The method involves analyzing statistical parameters derived from subsurface data to characterize fracture networks. These parameters include fracture density, which measures the number of fractures per unit volume; fracture length, which quantifies the extent of individual fractures; fracture orientation in space, which describes the spatial arrangement of fractures; fracture openness, which indicates the degree to which fractures are open or closed; and the distribution of fractures within the formation, which describes how fractures are spatially arranged. By evaluating these parameters, the method provides a comprehensive assessment of fracture network properties, enabling more accurate predictions of fluid flow and reservoir performance. The approach leverages subsurface data, such as seismic, well logs, or core samples, to derive these statistical parameters, enhancing the reliability of fracture characterization in geological formations. This method improves decision-making in subsurface resource management by providing detailed insights into fracture network behavior.
3. The method as claimed in claim 1 , wherein the equivalent permeability tensor of each mesh is determined by previously constructing a discrete fracture model for each mesh.
This invention relates to computational modeling of fractured geological formations, particularly for determining fluid flow and transport properties. The problem addressed is accurately representing the complex permeability behavior of fractured rock masses, where fractures significantly influence fluid movement but are difficult to model directly in large-scale simulations. The method involves constructing a discrete fracture model for each mesh element in a computational grid. This model explicitly represents fractures within each mesh, capturing their geometry, orientation, and connectivity. The discrete fracture model is then used to compute an equivalent permeability tensor for the mesh, which simplifies the complex fracture network into an effective property that can be used in larger-scale simulations. This approach allows for accurate representation of fracture-induced permeability while maintaining computational efficiency. The equivalent permeability tensor accounts for the anisotropic flow behavior caused by fractures, providing a more realistic simulation of fluid movement in fractured media compared to traditional methods that ignore or oversimplify fracture networks. The method is particularly useful in applications such as oil and gas reservoir simulation, groundwater flow modeling, and geothermal energy assessment, where accurate permeability representation is critical for reliable predictions.
4. The method as claimed in claim 2 , wherein the equivalent permeability tensor of each mesh is determined by previously constructing a discrete fracture model for each mesh.
A method for determining the equivalent permeability tensor of a mesh in a fractured porous medium involves constructing a discrete fracture model for each mesh. The discrete fracture model represents the fractures within the mesh, allowing for the calculation of fluid flow properties. The permeability tensor, which describes the directional permeability of the medium, is then derived from this model. This approach accounts for the complex interactions between fractures and the surrounding porous matrix, improving the accuracy of fluid flow simulations in subsurface environments. The method is particularly useful in applications such as oil and gas reservoir modeling, groundwater flow analysis, and geothermal energy assessment, where understanding fluid movement through fractured rock is critical. By incorporating fracture network details into the permeability tensor calculation, the method provides a more realistic representation of fluid transport compared to traditional homogeneous models. The discrete fracture model captures the geometry, connectivity, and properties of fractures, enabling precise determination of how fluids move through the fractured medium. This enhances the reliability of predictions for fluid extraction, injection, or migration in subsurface systems.
5. The method of claim 1 , wherein the characteristic dimension of the matrix blocks of the mesh is determined using a relationship which is a function of at least the eigenvalues of the equivalent permeability tensor and an equivalent surface permeability tensor which characteristic dimension is determined by at least steps: reorienting the principal directions of flow; determining for each principal direction of flow, the flow of the fluid leaving traces of fractures present on faces of a re-oriented mesh perpendicular to the principal direction; and determining for each principal direction of flow, the equivalent surface permeability in the direction of flow by equivalence of the flow with a flow representative of a homogeneous medium.
This invention relates to computational fluid dynamics, specifically methods for simulating fluid flow in fractured porous media. The problem addressed is accurately modeling fluid flow in complex fractured systems, where traditional mesh-based approaches often fail to capture the influence of fractures on permeability and flow behavior. The method involves determining the characteristic dimension of matrix blocks in a mesh by analyzing the equivalent permeability tensors of the fractured medium. The process begins by reorienting the principal directions of flow within the fractured system. For each principal flow direction, the method calculates the fluid flow leaving traces of fractures on the faces of a reoriented mesh perpendicular to that direction. This flow is then used to determine the equivalent surface permeability in the direction of flow by comparing it to a flow representative of a homogeneous medium. The characteristic dimension of the matrix blocks is derived from this relationship, incorporating the eigenvalues of the equivalent permeability tensor and the equivalent surface permeability tensor. This approach improves the accuracy of fluid flow simulations in fractured media by accounting for the anisotropic and heterogeneous nature of fractures.
6. The method of claim 2 , wherein the characteristic dimension of the matrix blocks of the mesh is determined using a relationship which is a function of at least the eigenvalues of the equivalent permeability tensor and an equivalent surface permeability tensor which characteristic dimension is determined by at least steps: reorienting the principal directions of flow; determining for each principal direction of flow, the flow of the fluid leaving traces of fractures present on faces of a re-oriented mesh perpendicular to the principal direction; and determining for each principal direction of flow, the equivalent surface permeability in the direction of flow by equivalence of the flow with a flow representative of a homogeneous medium.
This invention relates to computational fluid dynamics, specifically methods for determining the characteristic dimensions of matrix blocks in a fractured rock mesh to model fluid flow accurately. The problem addressed is the challenge of simulating fluid flow in fractured media, where fractures significantly influence permeability and flow paths. Traditional methods often fail to capture the complex interactions between fractures and the rock matrix, leading to inaccurate simulations. The method involves determining the characteristic dimension of matrix blocks in a fractured rock mesh by analyzing the equivalent permeability tensors of the system. The process begins by reorienting the principal directions of fluid flow within the mesh. For each principal flow direction, the method calculates the fluid flow leaving traces of fractures present on the mesh faces perpendicular to that direction. This flow is then used to determine the equivalent surface permeability in the direction of flow by comparing it to a flow representative of a homogeneous medium. The characteristic dimension of the matrix blocks is derived from this relationship, incorporating the eigenvalues of the equivalent permeability tensor and the equivalent surface permeability tensor. This approach ensures that the mesh accurately represents the fractured medium's flow behavior, improving simulation accuracy in subsurface fluid dynamics, such as oil and gas reservoir modeling or groundwater flow analysis.
7. The method of claim 3 , wherein the characteristic dimension of the matrix blocks of the mesh is determined using a relationship which is a function of at least the eigenvalues of the equivalent permeability tensor and an equivalent surface permeability tensor which characteristic dimension is determined by at least steps: reorienting the principal directions of flow; determining for each principal direction of flow, the flow of the fluid leaving traces of fractures present on faces of a re-oriented mesh perpendicular to the principal direction; and determining for each principal direction of flow, the equivalent surface permeability in the direction of flow by equivalence of the flow with a flow representative of a homogeneous medium.
This invention relates to computational fluid dynamics, specifically to methods for determining the characteristic dimensions of matrix blocks in a fractured porous medium. The problem addressed is accurately modeling fluid flow in fractured rock or similar materials where fractures significantly influence permeability. Traditional methods often oversimplify fracture networks, leading to inaccurate flow predictions. The method involves analyzing a mesh representing the fractured medium. The characteristic dimension of matrix blocks within the mesh is determined using a relationship based on eigenvalues of an equivalent permeability tensor and an equivalent surface permeability tensor. The process includes reorienting the principal directions of flow to align with the fracture network. For each principal flow direction, the method calculates the fluid flow leaving traces of fractures on mesh faces perpendicular to that direction. This flow is then used to determine the equivalent surface permeability in the direction of flow by comparing it to a flow representative of a homogeneous medium. The resulting characteristic dimension reflects the influence of fractures on fluid movement, improving the accuracy of permeability modeling in fractured systems. This approach enhances simulations for applications like oil and gas recovery, groundwater flow, and geothermal energy extraction.
8. The method of claim 4 , wherein the characteristic dimension of the matrix blocks of the mesh is determined using a relationship which is a function of at least the eigenvalues of the equivalent permeability tensor and an equivalent surface permeability tensor which characteristic dimension is determined by at least steps: reorienting the principal directions of flow; determining for each principal direction of flow, the flow of the fluid leaving traces of fractures present on faces of a re-oriented mesh perpendicular to the principal direction; and determining for each principal direction of flow, the equivalent surface permeability in the direction of flow by equivalence of the flow with a flow representative of a homogeneous medium.
This invention relates to computational fluid dynamics, specifically methods for determining the characteristic dimensions of matrix blocks in a fractured rock or porous medium. The problem addressed is accurately modeling fluid flow in fractured systems, where fractures significantly influence permeability and flow behavior. Traditional methods often oversimplify fracture networks, leading to inaccurate predictions. The method involves analyzing a mesh representing the fractured medium to determine the characteristic dimension of matrix blocks. This is done by first reorienting the principal directions of flow within the mesh. For each principal flow direction, the method calculates the fluid flow leaving traces of fractures on the faces of the mesh that are perpendicular to that direction. Then, for each principal direction, the equivalent surface permeability is determined by comparing the actual flow to a flow representative of a homogeneous medium. The characteristic dimension is derived from a relationship that depends on the eigenvalues of the equivalent permeability tensor and the equivalent surface permeability tensor. This approach ensures that the model accurately captures the influence of fractures on fluid flow, improving simulation accuracy in fractured reservoirs or porous media.
9. The method of claim 1 , comprising determining a criterion of acceptability of each mesh by using matrix blocks having an identical characteristic dimension.
This invention relates to a method for evaluating the acceptability of meshes in computational simulations, particularly in fields like finite element analysis (FEA) or computational fluid dynamics (CFD). The problem addressed is ensuring mesh quality, as poor mesh quality can lead to inaccurate simulation results. The method involves assessing mesh acceptability by analyzing matrix blocks within the mesh, where each block has an identical characteristic dimension. This ensures consistency in the evaluation process. The method may also include generating a mesh, refining it, and applying boundary conditions before acceptability assessment. The acceptability criterion is determined by comparing the mesh properties against predefined thresholds or standards. If the mesh fails to meet the criteria, it may be refined or adjusted to improve accuracy. The use of identical characteristic dimensions in matrix blocks ensures that the evaluation is uniform across the entire mesh, reducing variability in results. This approach helps automate mesh quality control, improving efficiency and reliability in computational simulations.
10. The method of claim 1 , wherein the mesh for which steps (A) to (D) is carried out is representation of a group of meshes of the double meshed representation which are determined based on at least one statistical parameter and in which in step (D) the characteristic dimension is assigned to the matrix blocks of the meshes of the group.
This invention relates to mesh processing in computational simulations, particularly for optimizing double meshed representations used in numerical simulations such as finite element analysis (FEA) or computational fluid dynamics (CFD). The problem addressed is the computational inefficiency and complexity of handling large-scale meshes, where detailed mesh resolution is unnecessary for all regions, leading to excessive memory and processing demands. The method involves selecting a group of meshes from a double meshed representation based on statistical parameters, such as variance, mean, or other metrics derived from simulation data. These parameters help identify regions where mesh refinement is critical versus those where coarser resolution suffices. The selected group undergoes a multi-step process: (A) identifying matrix blocks within the meshes, (B) determining a characteristic dimension (e.g., size, density) for each block, (C) assigning the characteristic dimension to the blocks, and (D) refining or simplifying the mesh structure based on this assignment. This ensures that computational resources are allocated efficiently, focusing on high-impact regions while reducing unnecessary detail elsewhere. The approach improves simulation accuracy where needed while minimizing computational overhead, making it suitable for large-scale simulations where performance and resource management are critical.
11. The method of claim 1 , wherein the optimum exploitation scheme is determining by a method of recovery of the fluid and number, a layout and a geometry of at least one of an injection and a production well which satisfies predefined technical and economic criteria.
This invention relates to optimizing fluid recovery from subsurface reservoirs, particularly in oil and gas extraction. The problem addressed is the need for an efficient and cost-effective method to determine the optimal exploitation scheme for extracting fluids from a reservoir. The solution involves a method that calculates the best recovery approach by analyzing the fluid recovery rate, the number, layout, and geometry of injection and production wells. The method ensures that the chosen scheme meets predefined technical and economic criteria, such as maximizing recovery efficiency while minimizing costs. The injection and production wells are strategically placed and designed to enhance fluid extraction performance. The technical criteria may include reservoir pressure maintenance, fluid flow dynamics, and well productivity, while economic criteria may involve capital expenditure, operational costs, and return on investment. By optimizing these factors, the method ensures that the reservoir is exploited in the most efficient and profitable manner. The invention is particularly useful in the oil and gas industry, where precise well placement and design are critical for maximizing resource recovery and minimizing environmental impact.
12. The method of claim 9 , wherein the exploitation of the fluid is an optimum exploitation scheme which drills least one injection and production well and producing the fluid by the recovery method.
This invention relates to an optimized fluid exploitation scheme for extracting fluids, such as oil or gas, from a subsurface reservoir. The method addresses the challenge of efficiently recovering fluids while minimizing costs and environmental impact by strategically drilling injection and production wells. The system involves a recovery method that maximizes fluid extraction by optimizing well placement and operational parameters. The exploitation scheme ensures that the wells are drilled in locations that enhance fluid recovery efficiency, reducing the number of wells needed and minimizing energy consumption. The method also accounts for reservoir characteristics, such as permeability and fluid properties, to determine the most effective recovery approach. By integrating well placement optimization with recovery techniques, the invention improves overall production rates while reducing operational expenses and environmental footprint. The system may include real-time monitoring and adjustment of well operations to maintain optimal recovery conditions. This approach is particularly useful in mature fields where traditional methods are no longer cost-effective. The invention provides a data-driven solution that enhances recovery efficiency and extends the productive life of reservoirs.
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May 5, 2020
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